Ladies and gentlemen, thank you for standing by, and welcome to the SM Energy Q3 2020 Financial and Operating Results Q&A Conference Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. I would now like to hand the conference over to your speaker, Jennifer Samuels, Vice President of Investor Relations. Please go ahead.

Thank you, Jacqueline. Good morning, everyone, and thank you for joining us. First, allow me to quickly remind you that we may discuss forward-looking statements about our plans, expectations and assumptions regarding future performance. These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. Please refer to the cautionary information about forward-looking statements in the 3Q earnings release, the IR presentation and the Risk Factors section of our Form 10-Q, which was filed this morning, all of which are posted to our website. Our discussion today may include discussion of non-GAAP financial measures that we believe are useful in understanding and evaluating our performance. Reconciliation of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are provided in our earnings release and IR presentation. Here to answer your questions this morning are our CEO, Jay Ottoson, who is joining us remotely while he is traveling; EVP and CFO, Wade Pursell; and President and COO, Herb Vogel. Before I turn it back to the operator, I want to say, this morning we announced that Jay's last day as CEO will be next week. Jay, I speak for many in saying that you will be missed and it has been a tremendous pleasure for me to work with you. Fortunately, he will remain on the Board until next year. So everyone, shall we go easy on him today. With that, I'll pass it back to the operator.

Thank you. Your first question comes from Steven Dechert from KeyBanc. Your line is open.

Hey. Just hoping to get a little bit more detail on the 4Q 2020 production guidance. Looks like it's down around 10% from 3Q 2020. Could you give maybe the number of permeability plan complete in 4Q 2020? Are they maybe coming on later in the quarter? Thanks.

Okay. Steve, this is Herb. I'll get that one. So let me just start on 4Q by saying that we probably shouldn't read too much into the production guidance, where we ultimately wind up on 4Q production just depends on which side of the end of the year we turn in line the new conclusions relative to our assumptions. Most of you who’ve followed us know this happens every year, a few new wells a few days early consuming volume significantly per quarter, especially the pad at six well zone for example. Also, October production is looking quite strong. And you may have also been noticing that we are getting more efficient rather than less efficient completing wells. We never bake efficiency intrusive into that guidance level that we put out there. So on your specific question, it's around 20 that will bring online, but that can move plus or minus two fairly easily. And we are intentionally working our program, but there are things that can push things back and there are things that can accelerate things, so that’s around 20 wells would actually come online. More will be completed because of the program, so we'll have some more DUCs at the end of the year. Does that help you?

Yes. That's great. And just as a follow-up. Just wanted to ask, with oil prices down in the last couple of days to around $36 a barrel WTI, has that maybe caused you guys to reevaluate this 2021 outlook for double-digit oil production growth at all? Thanks.

Steve, we don't react to short-term oil price fluctuation. We lay out a plan. Right now, we're starting to work the budget, which will complete in November, December, and we'll go from there, and we typically use strip in early January to make our call on it. So fluctuations right now would not influence us at all.

Okay. Great. Thanks.

This is Wade. I will add. As you're probably aware, we’ve been continuing to hedge as we typically do, especially the upcoming year. I think we've probably got somewhere in the ballpark of two thirds of oil compared to next year’s ballpark.

Okay. Awesome. That's great additional detail. Thank you.

Thanks.

Your next question comes from Michael Scialla from Stifel. Your line is open.

Yes. Thanks. And I'd like to echo Jennifer's sentiments to Jay as well. It's really a pleasure working with Jay over the years. I want to follow on to the last question. As you go into the planning process, if oil prices kind of stay here and looking at your – in conjunction with your Slide 11, you show – you have the lowest breakeven with but it’s a breakeven price in the high-30s. I’d say there’s a 12-month strip. Looks like it's going to be there when you plan next year. Any thoughts on running the three rigs in the play if strip prices stay here or even down a little bit, would you consider introducing the plan at all and maybe just focus on reducing the DUC inventory?

Well, Michael, we're working really on – as we take about 2021, 2022. So we really look at the metrics that are generating free cash flow. We’re working to pay down absolute debt. And we're making sure our leverage drops over time. So we'll be looking at what the strip price could look like in January when we make that determination. And obviously, costs are coming down that helps on our breakeven economics. And we have relatively high return hurdle and we're not going to be doing things that aren't at those hurdles there. And then the program we've got, as Jay just mentioned, two-thirds of our oil hedge next year also.

Great. Okay. And looking at your last three chalk wells, it looks like they actually have a lower breakeven oil price than your average Permian oil. I'm just curious how many – the 24 DUCs that you have in South Texas, how many of those are in chalk and any chance that – there's a larger portion of the 21 program that was this year.

So Michael, what we talked about before is that we had several scenarios with different levels of activity in the Permian in South Texas. And we got one. We picked both scenarios right now. But as we get into the budget process, we'll look at where prices are and what the well performance is looking like and make that determination. But we haven't locked in on that yet. Obviously going to be more Permian, which is because of how many DUCs we have there and the program that's underway and the three rigs we have running. Exactly how many completions we'll have, we'll lock that in later in the year. I think you're right. We're really pleased to see with high gas prices in particular, those breakevens really drop on those Austin Chalk wells and we're really pleased with what we're seeing. And we do have some DUCs, but really are drilling Austin Chalk right now.

Can you say Herb how many of those 24 DUCs are actually chalk wells and would you think they'd be comparable to the last three or are those primarily Eagle Ford wells?

So the completions for 2021 should be all Austin Chalk, and the number of DUCs of Austin Chalk, there are obviously many more Eagle Ford DUCs, but we’re not necessarily completing them. But we're not planning to complete them in 2021. But I don't want to put a number out there because I know it's got to be at least six, but I don't know how many more we've got right now. I know we just finished drilling a couple of them. So that would add to those six. So yes, it's not going to be more than half of those DUCs, that's for sure.

Okay. Thank you.

Your next question comes from Gail Nicholson from Stephens. Your line is open.

Good morning, Jay. Congrats on the retirement. It was a real pleasure working with you over the last couple of years. Looking at LOE, you guys lowered the full-year guide. When you look into kind of that 4Q 2020 and 2021 environment, how much of the LOE savings that you achieved in 2020 do you think is retainable?

Gail, this is Herb again. It's great to point that out because we've been doing great on the LOE side. All our costs have come lower plus. We were doing structural changes to embed those. The swing is going to be how many workovers we do. So in a low price environment, it's harder to justify doing workovers as prices improve, then you can justify more workovers. So that's always going to be a little bit of a swing. And the more we produced from South Texas that also reduces the LOE because Permian tends to wind up with a little bit higher LOE. So I think, we haven't given guidance yet for 2021 and we'll do that when we come out of the budget process.

Okay. Great. And then also in the prepared remarks, last night you talked about testing a higher cost completion design. Can you just provide some details on what that entails and what you're trying to achieve there?

We’ve seen some operators using some other completion designs, which look a little more costly, but may enhance the production where the return on the incremental spend is significant. And if that's the case and we see that, and then we would bake that into our budget for 2021. So you could have fewer completions that performed better, or you may have the same number that we are thinking and – but not quite as good as those enhancements, but we want to see how those wells perform before we make the call. And we want to have at least six to 12 months of production performance history to make an assessment there. And we may test some ourselves, or we may say, let's wait on this. Or we may say let's put them in place. So we haven't done them yet, put the budget together yet and we'll see where we get to them on those.

Okay. Great. Thank you.

Your next question comes from Gabe Daoud from Cowen. Your line is open.

Hey. Good morning, everyone, and congrats, Jay on your retirement. I was wondering if maybe you could elaborate a little bit more on the prepared remarks last night that indicated there, I guess, could be a potential for a small-scale JV and the dryer portion of your Eagle Ford asset. So just curious if you could maybe talk a little bit about potential timing or what the structure could look like?

Sure, Gabe. So we talked to third parties, some that just came to us and others that we had been talking to for quite a while, and it's really the combination of great recent well results and this improving outlook for natural gas and NGL prices. And it's getting quite a bit of attention as you're aware. So I can't really comment further on any discussion, but just keep an eye out. And if we do one well, we’ll probably issue an announcement, but we don't have it locked in yet. We don't have it in any of our guidance or plans at this time.

Okay. Understood. Thanks for that. And maybe just a follow-up. You had mentioned in the prepared remarks, essentially growing free cash flow in 2022 based on your pricing. And I think you'd also mentioned that assumes that capital spend would be lower than 2021. Could you maybe just elaborate a little bit more on those high-level goalposts for 2022?

Yes. That's true. We've talked about the things we're focused on, which is free cash flow generation, absolute debt reduction and leverage. And because we come out of 2021 with a high level of production, we continue to generate a lot of free cash flow in 2022 at strip prices. And what we'll do is we’ll see – as we get through 2021, we'll see where things look for 2022, but we're obviously looking to budget for 2021 just over the next several weeks.

The expectation is not that deflation, but we are assuming costs go down. It's current costs.

Yes. Current cost.

Great. Thank you, guys.

Your next question comes from Mike Scialla from Stifel. Your line is open.

Yes. I just want to follow-up. Wade, you said in your prepared remarks that you don't foresee any surprises on the redetermination. Can you say what the company asked for from the banks? Did you just request them to maintain the client base? This is where it stands now? Or any color you can add to the comments you made in your prepared remarks?

Sure, Mike. All I can really say is that you should expect something in the area of where we are. I think is what I would say. I don't want to give any specific numbers since we're going through the process right now. But I don't think you should be surprised and it should be in the area. Anything, frankly, it's a testament to the assets and how resilient they are, I think where your price is that I can say those remarks.

That's helpful. And on the cost side, Herb, you said you've been seeing better than $560 per foot, even though you haven't put it in the slide yet, but can you give any sense of how much better? And obviously, you think it's sustainable, you said you've taken it into your 2021 plan. I’m just wondering if that contemplated or included any changes in the well-design that contributed to that reduction. And it's specifically like lower frac intensity or any other changes that pushed that number down?

I mean, Michael, it's really just a combination of deflation, really strong execution on our part, and you've seen some peers with low numbers and let's just say, we're not going to be any worse than the best peers. But then when we look at completion design, we may do things where we put a little bit more in to get a better production especially as we've tested it. So that's why we said for – it's a good assumption just to use our $560 or a little bit less for 2021, but we haven't finalized yet what we're going to do there. We're evaluating right now. And that's really comes down to – so efficiencies, deflations and execution, that's really contributes to the lower cost.

Got it. Okay. And you mentioned, Herb, you could have strong production heading into 2022. Where do you see the base decline heading into 2021? And what do you need to spend there, if you just say, if oil prices aren't what you hope if you just want to maintain production at that fourth quarter level? Any idea on what sort of maintenance capital would be for 2021?

Yes. So the base decline on Permian was 48% a year ago, and now it's about 46% on South Texas. I think it was running around 29%, probably 27% now, somewhere in that range. And so as we go on, generally it drops somewhat depending on how many new well completions you have. And as you've seen 2021, we've said around 110 completions, which is a big uptick from this year. So that contributes to the strong production growth. We have scenarios that we can choose if we saw something materially different, in fact, we did in Q2. We adjusted our program for the change in commodity prices, and we have that flexibility here. We don't have to do anything, but add strip pricing, which is kind of the basis. We make our plan. That's what you've seen at current strip pricing. As we see significantly different strip prices in January, we adjust appropriately.

Okay. I think just a last one for me. I just want to follow-up on. Wade, you mentioned, some operators approaching you in the Eagle Ford dry area and realized you haven't done anything there yet, but that's – did say that you're seeing some significant well performance there. I assume other operators, somebody is active in that area. And curious based on what you're seeing there right now. What kind of gas price would you need to make sense of that area to be able to compete for capital?

Yes. So even if those that are new to JV, that's the economics that the JV partner would want to pursue. And the economics vary significantly depending on where it is in the field and in the liquid content. It's NGL-rich, obviously, and then there's quite a bit of condensate as you move through the North. So they vary quite a bit. I think if you look at Denver, they've got numbers out there for breakeven and you can see that the West Eagle Ford has good breakevens when you look at the current strip that they can make the return that people would expect. And I think that's what you're seeing happening. So you can see Western Eagle Ford activity picking up from other operators. We are focused on the Arkansas. We're not focused on trying to produce a bunch of dry gas in response to potential short-term market pricing.

Got it. Thank you.

There are no further questions at this time. I will now turn the call back over to Herb Vogel, President and COO for closing remarks.

Okay. Thank you, Jacqueline. So I'd like to just take a moment to thank Jay for his leadership and enormous contributions to SM Energy during his 14 years with the company and nearly six as CEO. He initiated the transformation that's led to our current status of the premier operator with truly top tier assets. The results we're seeing today are a testament to the success of his leadership. Personally, I've known Jay for many years. He is without a doubt an outstanding leader and individual of the highest integrity and passionate about supporting the communities where we live, work and operate. He has truly cared and taken action to ensure the safety and health of our employees and contractors. And that's been very visible during this COVID time. We wish him the best in a long, healthy, and enjoyable retirement. And with that, I'll turn the call over to Jay.

Well, thank you, Herb. It's always a mixed set of emotions you get on these last few days. I want to say how much I appreciate the opportunity I've had to work with all of you on the phone, all the analysts and our management team as well. I will say I'm extremely excited about the future of the company with Herb’s leadership. I think he's a terrific leader, a fantastic business person and he's going to do really well with the company. And I obviously – I certainly hope for our country and for our industry better times ahead. So I will look forward to all your success and wish you the very best. Thank you for your kind words today. Jennifer, over to you.

That's the end of the call. Thank you very much.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating and you may now disconnect.